1. Field of the Invention
The present invention relates generally to oil and gas flow production. In particular, a method and device according to the invention relates to a system for removal of accumulated liquid inhibiting the flow of gas producing wells.
2. Description of the prior art
Many gas wells produce liquids in addition to gas. These liquids include water, oil, and condensate. As described in the paper SPE 2198 of the Society of Petroleum Engineers of AIME, authored by R. G. Turner, A. E. Dukler, and M. G. Hubbard, "in many instances, gas phase hydrocarbons produced from underground reservoirs will have liquid-phase material associated with them, the presence of which can effect the flowing characteristics of the well. Liquids can come from condensation of hydrocarbon gas (condensate) or from interstitial water in the reservoir matrix. In either case, the higher density liquid phase, being essentially discontinuous, must be transported to the surface by the gas. In the event the gas phase does not provide sufficient transport energy to lift the liquids out of the well, the liquid will accumulate in the well bore. The accumulation of the liquid will impose an additional back pressure on the formation and can significantly affect the production capacity of the well". Over time, accumulated liquid can cause a complete blockage and provoke premature abandonment of the well. Removal of such liquid would restore the flow of gas and improve utilization and productivity of a gas well.
In essence, a two-phase flow usually exists in the well sometimes even at the beginning of its life. High pressure gas flow violently mixes with liquid droplets and moves them up the well with sufficient energy so as to remove the liquid out of formation or, at least to force the liquid droplets out of the upwardly moving stream of gas so as not to present any substantial flow resistance. In this two-phase flow, liquid-to-gas ratio is quite low and flow conditions are favorable for liquid removal. Well diameter and depth, gas pressure at the bottom and at the top of the well, and temperature are among the factors determining the flow structure and the resulting amount of liquid removal. Even in the case of some liquid accumulation, the gas pressure is still high enough to overcome the back pressure exerted by liquids and gas is produced up the well, albeit at a lower rate than if there were no accumulated liquid.
Over time, however, as the gas pressure in the formation declines and liquid invasion increases at the wellbore, the flow conditions may change. The mist flow transforms into an annular flow where the liquid runs up the casing wall and liquid droplets are entrained in the gas flow. As the pressure continues to decline, the annular flow loses its ability to move the liquid up and the droplets of liquid are forced against the wall of the gas casing rather then being removed out of the well. As the liquid tends to slide down to the bottom of the well in a falling film pattern, it accumulates in the lower sections of the well forming a liquid column. This column eventually develops a substantial height so as to increase the resistance to the gas flow. Often, accumulation of as little as 5 to 25 barrels of liquid a day may cause this effect. The two-phase flow conditions cease to exist and ultimately the liquid column completely blocks the gas from flowing upward.
There are many technical solutions that have been suggested in the prior art to solve the problem of accumulating liquids. Some of them are described briefly by E. J. Hutlas and W. R. Granberry in the article entitled "A Practical Approach to Removing Gas Well Liquids" in the Journal of Petroleum Technology, August 1972, p. 916-922. As the authors point out, sometimes wells are blown periodically to remove liquids along with thus very rapidly produced gas. In other cases, siphon tubing strings are run down the well and the pumper unloads the liquids from the well by opening such siphon tubing strings from time to time to atmospheric pressure. This siphon tubing string may have a typical diameter of 1 to 1 1/4 inch. Such system requires sometimes that the main flow is interrupted and even then the pressure at the bottom may not be enough to cause the liquid to flow through a smaller tube.
Occasional or permanent increase of the wellbore pressure was proposed to be used in order to ensure the formation of a favorable two-phase flow in the whole casing or at least in a smaller diameter liquid removal tube. A method and system for such periodic dewatering of a gas well is described in U.S. Pat. No. 4,226,284 by Evans. The flow through the casing is periodically shut off to increase the wellbore pressure so the water or other liquids can be blown off through the smaller liquid removal tube and into the main outlet together with some gas for further separation downstream. Alternately, the U.S. Pat. No. 5,211,242 describes a liquid removal chamber disposed at the bottom of the well with two tubing strings connecting the chamber with the top of the well. One tubing string is used to raise the pressure in the chamber while the other provides the flow path for liquid removal.
Various other injections are used for this purpose. U.S. Pat. No. 4,410,041 by Davies describes injection of a aqueous liquid solution which generates high pressure nitrogen gas. U.S. Pat. No. 4,276,935 by Hessert describes injection of a hydrocarbon-diluted water-in-oil emulsion comprising a viscosifying polymer such as polyacrylamide, the injected polymer swelling on contact with connate water to restrict transfer of water toward the producing gas well. U.S. Pat. No. 5,244,043 by Shuler discloses the injection of controlled quantities of a scaling cation brine and scaling anion brine such that the scale will precipitate, while the well is temporarily shut down, to reduce the permeability of the formation and prevent liquid from coming into vicinity of the well.
Injection of a foaming agent is proposed in U.S. Pat. No. 4,237,977 by Lutener as means to improve liquid removal conditions. Similar solution is contained in the U.S. Pat. No. 5,515,924 by Osterhoudt, whereby a solid stick is inserted into a well consisting of surfactant/chemical solution. This soap stick falls to the bottom of the well and transforms the liquid into a foam thus affecting favorably the conditions for liquid removal. All of the above solutions require additional complicated means to be available and procedures to be performed in order to influence the conditions forming a two-phase flow with high concentrations of liquid such as to promote its removal from the well. Also, the chemical additives often require separation in surface facilities prior to water disposal or condensate refining.
Mechanical water removal systems are also known in the prior art. U.S. Pat. No. 4,275,790 by Abercrombie discloses a water removal approach wherein the well contains a tubing string located inside the casing, with the tubing in contact with the accumulated liquid. Both the tubing and the casing are connected to the offlake line. Periodically, both the tubing and the casing flow are turned off so that the pressure in the wellbore is allowed to build up. Then, the tubing is opened to the offtake line that allows liquid to be discharged for further separation downstream.
A split-stream method for liquid removal from wells with low formation pressure is described in U.S. Pat. No. 4,509,599 by Chenoweth, wherein a compressor is employed to pump gas from a tubing string pathway disposed in the gas well to a gas pathway which runs up the annulus, thus unloading liquids from near the bottom of the well via the tubing pathway.
Finally, U.S. Pat. No. 5,636,693 by Elmer describes yet another tubing string system where both the tubing and the main casing are connected to the offtake line and having at least one choke means. The choke means preferably positioned in the casing annulus is used to control pressure in the tubing string and thus control liquid removal by increasing gas velocity up the tubing string to allow liquid mist to exit the well.
Most of the above prior art solutions fail to address directly the main phenomenon which causes liquid accumulation in the well in the first place. As described above, typically at the beginning of the well life, the diameter of the casing is sufficiently large to allow for both the high flow rate of gas needed for economically viable utilization of the well and, at the same time for such conditions of the gas and liquid two-phase flow so as to remove liquid from the well. With time, however, as the pressure declines and liquid invasion at the wellbore increases, two-phase flow conditions change, allowing the gas to slip by the liquid due to its lower density and viscosity. As this slippage increases, the liquid is ultimately left behind accumulating along the outer walls of the casing and moving down the well where it accumulates. Theoretically, it would be desirable to reduce the diameter of the casing in which case the slippage of gas past the liquid can be reduced. In fact, it was proposed to retrofit older wells with smaller diameter casings. However this would reduce the gas flow rate which eventually makes the well economically undesirable. Thus, the tubing string concept was proposed in the prior art to address the diameter question. Even though the diameter of the string is lower than the diameter of the well, it is still typically more then 1 or 1 1/4 inch which is considered necessary for sufficient rate of liquid removal. In addition to reducing the useful cross-section area of the main gas annulus and impeding the gas flow, in many cases this diameter still does not provide a sufficiently high liquid-to-gas ratio and associated low gas slippage and therefore for efficient liquid removal. Typically, these velocity strings depend on using the velocity of the gas liquid flow to entrain the liquid in the gas to reach the top of the well. Since high volume of gas is flowing up this tubing string, it has to be connected to the main offtake line or, alternately the gas has to be compressed before it is reintroduced downstream, where both of these options reduce system flexibility, demand more equipment to be used and increase production costs.
Therefore, the need exists for a liquid removal system with intrinsically high liquid-to-gas ratio for efficient liquid removal which is flexible in design to accommodate various well conditions, does not require gas flow interruptions, and occupies minimum space in the gas production conduit (casing or production tubing) so as not to reduce significantly the gas flow rate.